The success of drilling operations is heavily dependent on the drilling fluid. Drilling fluids cool down and lubricate the drill bit, remove cuttings, prevent formation damage, suspend cuttings and also cake off the permeable formation, thus retarding the passage of fluid into the formation. Typical micro or macro sized loss circulation materials (LCM) show limited success, especially in formations dominated by micropores, due to their relatively large sizes. In the current work, a new class of nanoparticle (NP) loss circulation materials has been developed. Two different approaches of NP formation and addition to oil-based drilling fluid have been tested. All NPs were prepared in-house either within the oil-based drilling fluid (in-situ), or within an aqueous phase (ex-situ), which was eventually blended with the drilling fluid. Under low pressure low temperature API standard test, more than 70% reduction in fluid loss was achieved in the presence of NPs compared to only 9% reduction in the presence of typical LCMs. The filter cake developed during the NP-based drilling fluid filtration was thin, which implies high potential for reducing the differential pressure sticking problem and formation damage while drilling. Moreover, at the level of NPs added, there was no material impact on drilling fluid viscosity and the fluid maintained its stability for more than 6 weeks.

Nanoparticles (NPs) are currently being studied as a drilling fluid additives especially for application in very lowpermeability formations such as shales. Application for conventional permeable rocks is still a subject of discussion. In this work, successful application of in-house prepared iron-based nanoparticles (NP1) and calcium-based nanoparticles (NP2) to reduce filtration loss in conventional permeable media has been experimentally quantified for oil-based mud (OBM) utilizing the high-pressure high-temperature (HPHT) filter press at 500 psi and 250°F. Ceramic discs were used as the filtration medium in this application to test the performance of the NPs and glide graphite as a conventional lost circulation material (LCM) for porous media. These experiments were carried out in the presence of graphite at low and high concentrations. Filtration reduction trends were observed and a reduction up to 76% was achieved. API filter press was also used to investigate the behavior of NPs and graphite under low pressure and temperature conditions (LPLT). NP1 and NP2 at the two graphite concentrations showed a reduction up to 100%. NP1 gave higher reduction especially at low concentrations under HPHT conditions, while NP2 yielded significant reduction at high concentration under HPHT. These trends were reversed under LPLT, giving a new insight on NPs performance under different pressure and temperature conditions. At HPHT and LPLT, the effect of graphite as a filtrate reduction agent is less significant as the NPs concentration increases. High graphite level had a positive effect on filtration reduction in combination with NP1 at HPHT and LPLT. This was not the case for the blends containing NP2 at HPHT. The effect of NPs and graphite was tested individually showing a different performance compared to the combination of them. Impact of NPs and graphite on rheology was also quantified allowing identification of the more sensitive parameters in the blends. It is concluded from this study that blends containing NPs and graphite can be successfully implemented in OBM to minimize formation damage in porous media.

Summary This paper presents a new friction model for application in petroleum wells. Although very simple, it applies for all wellbore shapes such as straight sections, drop-off bends, build-up bends, side bends or a combination of these. The drillstring is modelled as a soft string. In high tension the string weight is negligible as compared to the tension. This leads to simplified equations where the friction caused by the weight is negligible. For this case the friction in a bend is formulated in terms of the 3D dogleg. The same model therefore applies for 2D and 3D wellbores. The entire well can be modelled by two sets of equations, one for straight wellbore sections and one for curved wellbores. The latter is based on the absolute directional change, or the dogleg of the wellbore. Three worked examples are given in the paper: a 2D well, a 3D well and combined hoisting and rotation in the 3D well. One main purpose of this paper is to provide a simple explicit tool to model and to study friction throughout the well by separating gravitational and tensional friction effects.

In certain areas, the use of aerated mud as a circulating medium for drilling oil and gas wells is becoming an attractive practice. This is because aerated drilling has many advantages over conventional mud drilling, such as a higher penetration rate, less formation damage, minimized lost circulation, and lower drilling cost. The importance of maintaining adequate air and mud flow rates is generally recognized in aerated drilling operations. However, it remains unclear to drilling operators as to what constitutes an "adequate flow rate." On the basis of computer simulation, this paper discusses carrying capacity of an aerated mud and the optimum air-injection rate that ensures a maximum penetration rate. It is found in this study that the carrying capacity of an aerated mud is very different from that of both the conventional mud and pure air. There is an unfavorable range of mud flow rate that provides lower carrying capacity of the aerated fluid for a given air injection rate. As a unique characteristic of multiphase flow, there exists an air injection rate that gives the lowest flowing annulus pressure for a given well geometry and a mud rate. By considering both the carrying capacity and flowing annulus pressure, an optimum combination of mud and air rates can be determined. This optimum combination of flow rates should ensure a maximum penetration rate for a given well geometry. This paper provides drilling operators with a means of optimizing aerated mud drilling.

Summary In this paper, a new drilling optimization procedure is presented that is designed to improve the drilling efficiency with positive displacement motors (PDMs) and PDC bits. This developed optimization method is based on predicting rate of penetration (ROP) from PDM outputs for any PDC bit design. More specifically, optimization is done for a hole section and optimum values of weight on bit (WOB) and surface RPM are obtained for the section. For given flow rates, estimated values of optimum WOB and surface RPM are used to calculate the corresponding motor differential pressures and the foot by foot ROP values. Also, the method is used to show how improper operational parameter selection can affect total drilling time. A case study was done to consider different PDMs with different lobe configurations and a set of fixed operational parameters. The presented method is verified by generating a confined rock strength log based on drilling data for a previously drilled well in Alberta. This foot-by-foot strength log is compared to a confined rock strength log generated as a follow-up analysis by a commercially available drilling simulator package. Also, a PDM differential pressure log is generated and compared to field-recorded on-bottom differential pressure values. The method's application is best demonstrated by simulating the drilling operation of the Alberta well with three different PDMs. It is shown that consideration of PDM performance/selection in the drilling planning phase will help to perform a safe and cost-effective operation by preventing motor stalls and maintaining highest average ROP for the section. It is also shown that by optimizing WOB and surface RPM values for a constant mud flow rate and predefined bit wear at total depth, a maximum average ROP for the section can be reached for any PDM.